Stringent environmental standards of emissions of sulfur and nitrogen compounds, together with low sulfur specifications for petroleum products, have resulted in making sulfur management critical in the operation of the modern refinery and in the recovery of natural gas liquids. Other processes where such sulfur management is important include smelting of various sulfide-containing ores, the sweetening of sour natural gas, destructive distillation of coal and oil shale, gasification or liquefaction of coal, and the production and use of hydrogen sulfide containing geothermal steam and liquid for generating electricity. Modern refineries are processing crude oils with higher sulfur contents and using processing which converts more of the heavier portion of the crude oil. Demands for cleaner fuels and cleaner air will increase the need for more efficient sulfur recovery processes.
Typically, sulfur management within a petroleum refinery comprises two basic processes: amine treating and sulfur recovery. Amine treating units remove hydrogen sulfide from recycle gas streams in hydroprocessing operations and from fuel gas and liquefied petroleum gas recovery units. In recycle gas treating, the sulfur in the crude oil portion reacts with hydrogen at elevated pressure to form hydrogen sulfide. The reactor product stream is flashed and a recycle gas stream containing hydrogen, hydrogen sulfide, and some hydrocarbons is sent to an amine adsorber wherein the hydrogen sulfide is removed by the circulating amine stream. In fuel gas and liquefied petroleum gas recovery units, the off-gases and stabilizer overheads from other refinery process units such as cracking, coking, and reforming units are sent to gas recovery units to collect the gas streams. Hydrogen sulfide is removed from the collected gas stream at low pressure by the circulating amine. In either case, the gas withdrawn from the amine units, an aqueous process, is a water-saturated acid gas which generally comprises carbon dioxide, hydrogen sulfide, and traces of aromatic hydrocarbons.
The effluent from the amine treating unit is passed to a sulfur recovery unit which typically converts the hydrogen sulfide to elemental sulfur. The widely used Claus sulfur recovery process comprises a thermal recovery stage followed by two or three stages of catalytic recovery. In the thermal recovery stage, the acid gas is burned in a reaction furnace with air or oxygen to combust approximately one-third of the hydrogen sulfide plus any hydrocarbons and ammonia in the acid gas. The sulfur dioxide from the combustion reacts in the reaction stages with the unconverted hydrogen sulfide to form elemental sulfur. The products of both the combustion and the reaction are cooled in a waste heat boiler and thermal sulfur condenser to recover the sulfur. The catalytic recovery zones contain an alumina catalyst which can suffer significant reduction in activity and selectivity when aromatic hydrocarbons are present in the waste gas feed stream. In a paper entitled, "Activated Carbon Cleanup of the Acid Gas Feed to Claus Sulfur Plants", by Lewis G. Harruff and Stephen J. Buskuhl, which was presented at the 75.sup.th Annual Gas Processing Association Convention in Denver, Colo., Mar. 11-13, 1996, the problem of aromatic hydrocarbons in waste gas feed streams to a Claus unit is disclosed. The authors employ an activated carbon adsorbent guard bed to remove the aromatic hydrocarbons. The authors point out the advantage of removing the aromatic hydrocarbons, but also indicate that the relative humidity of the waste feed stream must be maintained below 50 percent at which point the adsorption efficiency of the activated carbon drops off dramatically.
A number of other sulfur recovery processes in commercial use for removing hydrogen sulfide from waste gas feed streams include processes wherein the hydrogen sulfide is oxidized in the gas phase or in an aqueous liquid phase. One vapor phase process, known in the art as the Selectox Process is disclosed in U.S. Pat. No. 4,528,277 and U.S. Pat. No. 4,576,814 which are hereby incorporated by reference. These patents disclose the use of a catalyst comprising bismuth and vanadium components supported on a hydrophobic crystalline material. The catalyst is highly active and stable, especially in the presence of water vapor, for oxidizing hydrogen sulfide to sulfur or sulfur dioxide by the reaction of the hydrogen sulfide with oxygen.
Another example of a hydrogen sulfide removal process is the Stretford process which is disclosed in U.S. Pat. No. 4,892,723 and hereby incorporated by reference. The Stretford process produces a high purity sulfur product in an aqueous washing solution which absorbs and oxidizes hydrogen sulfide. The washing or absorption step is typically performed with a water-soluble organic alkaline agent, such as anthraquinone disulphonic acid (ADA), with the hydrogen sulfide being oxidized to particles of elemental sulfur by an oxidation promoter such as a pentavalent vanadium compound such as sodium vanadate (NaVO.sub.3). Recovery of the sulfur is obtained by floatation, using a stream of air which is injected into the process solution. This air injection generates a frothy slurry containing the sulfur particles. The sulfur particles rise to the top of the solution where they are skimmed off and recovered by filtration or other liquid/solid separation techniques. In this process, the oxygen in the injected air also serves to re-oxidize the reduced vanadate ions, thereby regenerating the aqueous alkaline washing solution for reuse in the process. U.S. Pat. No. 4,283,379 describes a similar process wherein the washing solution comprises a solubilized vanadium salt as the oxidizer, a non-quinone aromatic absorption compound, thiocyanate ions, and a water soluble carboxylate complexing agent. Other processes are based on the use of other metallic oxidizers such as ferric iron and soluble arsenates and stannates. One relatively recent process disclosed in U.S. Pat. No. 5,354,545 discloses a process for removal of sulfur compounds from a gas feed stream wherein the stream is contacted with an aqueous solution containing sulfide oxidizing bacteria in the presence of oxygen to oxidize the hydrogen sulfide to elemental sulfur.
A commonly used technique to remove the sulfur particles from aqueous solutions is by circulating the washing solution through a tank-like oxidizer vessel, through which air is bubbled to re-generate the washing solution and form a frothy slurry. When these solutions are fresh, the elemental sulfur particles which are formed have an average diameter ranging between about 0.5 and about 5.0 microns. These particles typically agglomerate to form sulfur clumps of about 10 to about 150 microns in size. Such agglomerated particles are readily buoyed up to the surface of the froth and pass-through a weir-like opening near the top of the vessel into a sulfur collection vessel. Here, the bubbles in the froth readily collapse, and resultant liquid suspension or slurry can easily be pumped to a sulfur separation device such as a rotary vacuum filter, filter press, or centrifuge, from which, after washing to remove the entrained process solution, an extremely pure grade of sulfur is obtained. Where a non-particulate form of sulfur is desired, a washed filter cake may be sent to an autoclave or other sulfur melter.
A problem which was pointed out in U.S. Pat. No. 4,892,723 and in the above-mentioned article related to the Claus process is the introduction of contaminants such as aromatic hydrocarbons having from six to eight carbon atoms per molecule. These hydrocarbons may be introduced by the incomplete or improper combustion of the sulfur contaminated waste stream in an oxidation step, or by the incomplete separation in a process plant, such as the amine unit, supplying the basic feedstock for this process. When these contaminants appear, even in trace amounts, they accelerate the rate of formation of certain contaminants such as thiosulfates in the washing solution which result in the promotion of long-lasting, highly stable foams in the oxidizer vessel, which causes the formation of "sticky" sulfur particles and makes the subsequent sulfur separation and washing in the filter quite difficult. In U.S. Pat. No. 4,892,723, the solution to the problem was the contacting by at least a portion of the incoming contaminated gas stream or the already contaminated washing solution with a charcoal or other carbonaceous adsorbent useful for removing the contaminants. The solution in the Claus process was also the use of an activated carbon guard bed to adsorb the aromatic hydrocarbons. Unfortunately, such carbonaceous adsorbents become ineffective when both aromatic hydrocarbons and water are present in the gas stream containing the hydrogen sulfide.
Generally, thermal swing processes utilize the process steps of adsorption at a low temperature, regeneration at an elevated temperature with a hot purge gas and subsequent cooling down to the adsorption temperature. One process for drying gases generally exemplary of thermal swing processes is described in U.S. Pat. No. 4,484,933 issued to Cohen. The patent describes basic thermal swing processing steps coupled with the use of an auxiliary adsorber bed for improving the regeneration step. Thermal swing processes are often used for drying gases and liquids and for purification where trace impurities are to be removed. Often, thermal swing processes are employed when the components to be adsorbed are strongly adsorbed on the adsorbent, i.e., water, and thus, heat is required for regeneration.
Improved processes are sought which permit the adsorption of the aromatic hydrocarbons in the presence of water and other competing species from the waste gas stream which already contains high levels of hydrogen sulfide and acid gases such as carbon dioxide. It is the object of the present invention to provide an improved sulfur production process which is not limited by the presence of water or aromatic hydrocarbons, or aromatic hydrocarbons in the presence of water in producing a high purity sulfur product.